There are many enhanced recovery methods used to maximize the total oil recovered from fields. Unfortunately, even after the latest techniques are used, vast oil resources are left unproduced.
Lateral wellbores offer the potential to drain more oil than would be recovered otherwise. Laterals can be used to tap fresh oil by intersecting fractures, penetrating pay discontinuities, and draining up-dip traps. Lateral re-completions can also be used to correct production problems, such as water coning, gas coning, and excessive water cuts from hydraulic fractures which extend below the oil-water interface. Synergistic benefits may result from coupling lateral re-completions with enhanced recovery techniques to solve conformance problems, to contact un-swept oil by re-completing injection wells, and to re-direct sweep by converting existing well patterns into line-drive configurations. Lateral re-completions strategies can take advantage of the current production infrastructure, capital resource of existing wellbores, known resources of oil in place, and secondary and tertiary recovery technology.
When drilling laterals the rate of inclination change is usually described by the radius of curvature of the borehole. This is different from conventional drilling where curved boreholes are often described by the build or drop rate in degrees per 100 feet. A "short radius" curve is generally considered to have a radius of curvature of less than 150 feet. A "medium radius" is about 150 to 300 feet and a "long radius" curve is anything beyond 300 feet. For comparison, a 5 degree per 100 feet build is approximately equal to a 1,000 foot radius curve. None of the various curve rates (short, medium, long) are inherently better than the others. Depending on the objectives for a given well and the constraints of the situation, one curve rate will often be more suitable than another. However, as a general rule, short radius curves are often more desirable in re-completions where there is minimal open hole between the casing seat and the target zone. The shorter the radius, the less likely a section will need to be removed from the casing. Short radius curves also allow submersible pumps to be located close to pay zones. And the shorter the curve, the less formation above the target zone will need to be penetrated. This may reduce the problems associated with having open hole exposed to unstable shales, gas caps, and other producing zones. As the radius of curve gets smaller, so does the length of the lateral which can be drilled. Small radius curves also restrict the types of completions which can be performed. For example, it would not be realistic to case a 30 foot radius curve conventionally.
When drilling a curved borehole having a short radius of curvature, a flexible or an articulating drill pipe section is added to the curve drilling assembly (e.g., see U.S. Pat. Nos. 5,210,533 and 5,194,859 assigned to Amoco Corporation). The articulating section typically comprises short sections of pipe having articulating joints, or the like, as would be known to one skilled in the art. The articulating section is provided so the drill string does not impair the ability of the curve drilling assembly to drill a short radius curved borehole (i.e., a conventional drill string often does not have enough flexibility to traverse the short radius curved borehole and therefore may not allow the assembly to drill a short radius curved borehole and, if it is placed in a short radius curve, it may fatigue and fail after only a few rotations). The articulating section preferably extends uphole from the curve drilling assembly through the curved portion of the borehole.
Articulated drill collars are commonly called "wiggly pipe". They are constructed by cutting a series of interlocking lobed patterns through the wall of steel drill collars (e.g., see U.S. Pat. Nos. 4,483,721 and 4,476,945). Each such collar is fitted with a high pressure hydraulic hose and seal assembly. Historically, these collars have been the only reasonable option for rotating through a short radius curve, but they are not ideal because they attempt to straighten under compressive loading, cause the drillstring to rotate rough, complicate the procedure for orienting the deflection sleeve and are difficult to handle.
A major impediment to the widespread use of lateral re-entries is that drilling and completion of the laterals must be done economically. Workover economics in mature fields requires substantial cost reductions over the methods most often used for drilling new horizontal wells. Thus, there is a continuing need for reliable reduced-cost lateral drilling systems and tools, particularly tools that are easy to use with commonly used components and parts of curved drilling systems.
One situation that often occurs is the need to enlarge or widen a curved section of a well bore after the curve drilling is completed. For example, it is sometimes helpful to open a 33/4" or a 315/16" curve to 43/4". The larger opening facilitates running the lateral drilling assembly and reduces the torque required to rotate wiggly pipe in the curved section while lateral drilling. Opening the hole also makes the wiggly pipe more "fishable" in case it becomes lost in the hole. If a 43/4" drill bit or a conventional 43/4" PDC reaming tool (e.g., see U.S. Pat. Nos. 1,332,841; 4,431,065; and 3,851,719) was used to do this, drilling torque would be very erratic and the penetration rate would be slow. Moreover, existing reaming tools have not been proven to be very durable. Clearly, improvement is needed.